1. Field of the Invention
The invention relates generally to the field of well logging. More particularly, the invention relates to improved techniques in which instruments equipped with antenna systems having transverse or tilted magnetic dipole representations are used for electromagnetic measurements of subsurface formations and for placing wells with respect to geological boundaries in a reservoir. The invention has general application in the well logging art, but is particularly useful in logging-while-drilling operation.
2. Background of the Related Art
Various well logging techniques are known in the field of hydrocarbon exploration and production. These techniques typically use instruments or tools equipped with sources adapted to emit energy into a subsurface formation that has been penetrated by a borehole. In this description, “instrument” and “tool” will be used interchangeably to indicate, for example, an electromagnetic instrument (or tool), a wire-line tool (or instrument), or a logging-while-drilling tool (or instrument). The emitted energy interacts with the surrounding formation to produce signals that are then detected and measured by one or more sensors. By processing the detected signal data, a profile of the formation properties is obtained.
Electromagnetic (EM) induction and propagation logging are well-known techniques. The logging instruments are disposed within a borehole to measure the electrical conductivity (or its inverse, resistivity) of earth formations surrounding the borehole. In the present description, any reference to conductivity is intended to encompass its inverse, resistivity, or vice versa. A typical electromagnetic resistivity tool comprises a transmitter antenna and one or more (typically a pair) receiver antennas disposed at a distance from the transmitter antenna along the axis of the tool (see FIG. 1).
Induction tools measure the resistivity (or conductivity) of the formation by measuring the voltage induced in the receiver antenna(s) as a result of magnetic flux induced by currents flowing through the emitting (or transmitter) antenna. An EM propagation tool operates in a similar fashion but typically at higher frequencies than do induction tools for comparable antenna spacings (about 106 Hz for propagation tools as compared with about 104 Hz for the induction tools). A typical propagation tool may operate at a frequency range of 1 kHz-2 MHz.
Conventional transmitters and receivers are antennas formed from coils comprised of one or more turns of insulated conductor wire wound around a support. These antennas are typically operable as sources and/or receivers. Those skilled in the art will appreciate that the same antenna may be use as a transmitter at one time and as a receiver at another. It will also be appreciated that the transmitter-receiver configurations disclosed herein are interchangeable due to the principle of reciprocity, i.e., the “transmitter” may be used as a “receiver”, and vice-versa.
The antennas operate on the principle that a coil carrying a current (e.g., a transmitter coil) generates a magnetic field. The electromagnetic energy from the transmitter antenna is transmitted into the surrounding formation, and this transmission induces eddy currents flowing in the formation around the transmitter (see FIG. 2A). The eddy currents induced in the formation, which are functions of the formation's resistivity, generate a magnetic field that in turn induces an electrical voltage in the receiver antennas. If a pair of spaced-apart receivers is used, the induced voltages in the two receiver antennas will have different phases and amplitudes due to geometric spreading and absorption by the surrounding formation. The phase difference (phase shift, φ and amplitude ratio (attenuation, A) from the two receivers can be used to derive the resistivity of the formation. The detected phase shift (φ) and attenuation (A) depend on not only the spacing between the two receivers and the distances between the transmitter and the receivers, but also the frequency of EM waves generated by the transmitter.
In conventional induction and propagation logging instruments, the transmitter and receiver antennas are mounted with their axes along the longitudinal axis of the instrument. Thus, these tools are implemented with antennas having longitudinal magnetic dipole (LMD) representations. An emerging technique in the field of well logging is the use of instruments including antennas having tilted or transverse coils, i.e., where the coil's axis is not parallel to the longitudinal axis of the tool. These instruments are thus implemented with a transverse or tilted magnetic dipole (TMD) antenna. Those skilled in the art will appreciate that various ways are available to tilt or skew an antenna. Logging instruments equipped with TMD antennas are described, e.g., in: U.S. Pat. Nos. 6,163,155; 6,147,496; 5,115,198; 4,319,191; 5,508,616; 5,757,191; 5,781,436; 6,044,325; and 6,147,496.
FIG. 2A presents a simplified representation of eddy currents and electromagnetic (EM) energy flowing from a logging instrument disposed in a borehole portion or segment that penetrates a subsurface formation in a direction perpendicular to the sedimentation layers. This is not, however, an accurate depiction of all the numerous segments that make up a borehole particularly when the borehole has been directionally-drilled as described below. Thus, segments of a borehole often penetrate formation layers at an angle other than 90 degrees, as shown in FIG. 2B. When this happens, the formation plane is said to have a relative dip. A relative dip angle, φ, is defined as the angle between the borehole axis (tool axis) BA and the normal N to the plane P of a formation layer of interest.
Drilling techniques known in the art include drilling boreholes from a selected geographic position at the earth's surface, along a selected trajectory. The trajectory may extend to other selected geographic positions at particular depths within the borehole. These techniques are known collectively as “directional drilling” techniques. One application of directional drilling is the drilling of highly deviated (with respect to vertical), or even horizontal, boreholes within and along relatively thin hydrocarbon-bearing earth formations (called “pay zones”) over extended distances. These highly deviated boreholes are intended to greatly increase the hydrocarbon drainage from the pay zone as compared to “conventional” boreholes which “vertically” (substantially perpendicularly to the layering of the formation, as shown in FIG. 2A) penetrate the pay zone.
In highly deviated or horizontal borehole drilling within a pay zone, it is important to maintain the trajectory of the borehole so that it remains within a particular position in the pay zone. Directional drilling systems are well known in the art which use “mud motors” and “bent subs,” as well as other means, for controlling the trajectory of a borehole with respect to geographic references, such as magnetic north, the earth's gravity (vertical), and the earth's rotational velocity (with respect to inertial space). Layering of the formations, however, may be such that the pay zone does not lie along a predictable trajectory at geographic positions distant from the surface location of the borehole. Typically the borehole operator uses information (such as LWD logs) obtained during borehole drilling to maintain the trajectory of the borehole within the pay zone, and to further verify that the borehole is, in fact, being drilled within the pay zone.
Techniques known in the art for maintaining trajectory are described for example in Tribe et al., Precise Well Placement using Rotary Steerable Systems and LWD Measurement, Society of Petroleum Engineers, Paper 71396, Sep. 30, 2001. The technique described in this reference is based upon LWD conductivity sensor responses. If, as an example, the conductivity of the pay zone is known prior to penetration by the borehole, and if the conductivities of overlying and underlying zones provide a significant contrast with respect to the pay zone, a measure of formation conductivity made while drilling can be used as a criterion for “steering” the borehole to remain within the pay zone. More specifically, if the measured conductivity deviates significantly from the conductivity of the pay zone, this is an indication that the borehole is approaching, or has even penetrated, the interface of the overlying or underlying earth formation. As an example, the conductivity of an oil-saturated sand may be significantly lower than that of a typical overlying and underlying shale. An indication that the conductivity adjacent the borehole is increasing can be interpreted to mean that the borehole is approaching the overlying or the underlying formation layer (shale in this example). The technique of directional drilling using a formation property measurement as a guide to trajectory adjustment is generally referred to as “geosteering.”
In addition to EM measurements, acoustic and radioactive measurements are also used as means for geosteering. Again using the example of an oil-producing zone with overlying and underlying shale, natural gamma radioactivity in the pay zone is generally considerably less than the natural gamma ray activity of the shale formations above and below the pay zone. As a result, an increase in the measured natural gamma ray activity from a LWD gamma ray sensor will indicate that the borehole is deviating from the center of the pay zone and is approaching or even penetrating either the upper or lower shale interface.
If, as in the prior examples, the conductivity and natural radioactivity of the overlying and underlying shale formations are similar to each other, the previously described geosteering techniques indicate only that the borehole is leaving the pay zone, but do not indicate whether the borehole is diverting out of the pay zone through the top of the zone or through the bottom of the zone. This presents a problem to the drilling operator, who must correct the borehole trajectory to maintain the selected position in the pay zone.
EM induction logging instruments are well suited for geosteering applications because their lateral (radial) depth of investigation into the formations surrounding the borehole is relatively large, especially when compared to nuclear instruments. The deeper radial investigation enables induction instruments to “see” a significant lateral (or radial) distance from axis of the borehole. In geosteering applications, this larger depth of investigation enables the detection of approaching formation layer boundaries at greater lateral distances from the borehole, which provides the drilling operator additional time to make any necessary trajectory corrections. Conventional propagation-type instruments are capable of resolving axial and lateral (radial) variations in conductivity of the formations surrounding the instrument, but the response of these instruments generally cannot resolve azimuthal variations in the conductivity of the formations surrounding the instrument. Furthermore, such instruments are unable to sense anisotropy in vertical wells.
Two important emerging markets make the removal of these shortcomings more urgent. The first emerging field is the increasing need for accurate well placement, which requires directional measurements to make steering decisions to place the borehole optimally in the reservoir. The second is the low resistivity pay in laminated formations where accurate identification and characterization of hydrocarbon reserves is not possible without knowing the resistivity anisotropy. Many recent patents disclose methods and apparatus to make directional measurements and obtain resistivity anisotropy. For logging while drilling applications, U.S. Pat. No. 5,508,616 to Sato et al. discloses an induction-type tool with two coils tilted at different directions not aligned with the tool's longitudinal axis. The directionality of the measurement is illustrated through a simple argument that the sensitivity function of the two tilted coils is concentrated towards the overlapping region of the sensitivity area of each coil. Through rotation of the tool, Sato et al claim that a deep azimuthal resistivity image of the formation can be obtained. However, this patent reference does not provide any details as to how the azimuthal resistivity can be obtained, nor does it describe any further boundary detection/characterization techniques required for quantitative geosteering decision-making.
U.S. Pat. No. 6,181,138 to Hagiwara and Song extends Sato et al's single fixed directional coils into co-located triple orthogonal induction coils at the transmitter and receiver location. No tool rotation is said to be required, since the focusing direction can be tuned to arbitrary orientation through linear combination of the orthogonal coil responses. It is not clear if there is a shield design that will allow the passing of all the required EM components without severe uncontrollable distortion of the wave form for “while drilling” applications.
U.S. Pat. No. 6,297,639 to Clark et al., assigned to the assignee of the present invention, discloses methods and apparatus for making directional measurements utilizing various shield designs to provide selected attenuation of EM wave energy for axial, tilted, and transverse antenna coils. This patent reference describes, among other things, general directional induction and propagation measurements with tilted coils and appropriate shields, along with a process for conducting borehole compensation for them which is non-trivial. A one-axial and one-tilted transmitter/receiver coil combination is explicitly described by Clark et al., along with its application for bed boundary direction detection by observing azimuthal variation of the induced signal as the tool rotates. The azimuthal variation of the coupling can be used for steering wells while drilling. More shield patents have since been granted, including U.S. Pat. No. 6,351,127 to Rosthal et al., and U.S. Pat. No. 6,566,881 to Omeragic et al, both of which are assigned to the assignee of the present invention.
U.S. Pat. No. 6,476,609 to Bittar extends an earlier anisotropy patent describing both transmitters and receivers possibly having a tilt angle, U.S. Pat. No. 6,163,155 also to Bittar, to the area of geosteering application. The bedding response of up/down tilted induction and propagation apparatus is described through the difference or ratio of signals at two different orientations, but no shielding is mentioned. Nor are the effects of anisotropy or dipping considered. Also lacking is a description of how to use these measurements to derive a precise distance to a formation bed boundary. The '609 patent implicitly assumes that bedding orientation is precisely known so as to calculate the up/down response. No technique, however, is disclosed to locate the precise up or down direction prior the calculation of the up-down directional signals.
U.S. patent application Publication No. 2003/0085707 to Minerbo et al, assigned to the assignee of the present invention, discloses tool configurations and symmetrization techniques that simplify the response of the directional measurements to the point that it becomes almost independent to anisotropy or dipping angle. Responses to bed boundary distance with different dip and anisotropy essentially overlap except near the bed boundary. Both two-coil (one transmitter and one receiver: “TR”) induction style and three-coil (one transmitter and two receivers: “TRR”) propagation-style measurements can be symmetrized to achieve this simplification. The symmetrization is done between two tilted TR pairs of the same spacing, but with the transmitter tilted angle and receiver tilted angle exchanged. Only cases where the magnetic moments of the transmitters and receivers are lying in the same plane is considered. This has a disadvantage of not being able to provide the required signal for geosteering all the time during sliding, which is the case for well placement with a mud motor during the angle build on the trajectory. If the magnetic moment of the tool happens to lie parallel to the bedding during sliding, the up/down directional signal generated will be zero independent of the distance to the boundary. Thus no monitoring of the distance to the boundary is possible.
U.S. patent application Publication No. 2003/0200029 to Omeragic et al, also assigned to the assignee of the present invention, discloses propagation-style directional measurements for anisotropy determination in near-vertical wells with borehole compensation. Inversion techniques are also used to obtain the anisotropic formation property. U.S. patent application Publication No. 2003/0184302 to Omeragic and Esmersoy, assigned to the assignee of the present invention, also discloses techniques for looking-ahead with directional measurements.
U.S. patent application Publications No. 2004/0046560A1 and 2004/0046561A1 to Itzkovicz et al, discloses the use of quadrupole antennas, and transverse dipolequadrupole coupling and induction style measurements with similar directional characteristics to a conventional cross-dipole XZ response. Practical realization on a metallic collar and adequate shielding of such antennas is not clear. Also, the borehole effect of such measurements and its interaction/coupling with the boundary effect may be different from XZ-style measurements.
None of the above patent references discloses the use of detailed azimuthal responses of the measured signal or techniques to extract such responses. These references further fail to teach how to use the directional measurement to arrive at boundary distances for geosteering use. Only the so-called up/down measurement, which is the difference in the measured signal between the tool focusing directly towards and away from the formation bed, is mentioned. The precise bedding dip and azimuth information is usually not known before the drilling, and they also frequently vary in challenging well placement situations where geosteering is required. Using a predefined bedding up/down direction produces at best degraded measurement and at worst can lead to wrong geosteering decisions when the bedding azimuth suddenly changes. In principle, the measurements can be binned azimuthally downhole. This technique has a number of drawbacks including difficulties in aligning the top and bottom bins precisely with the orientation of the formation bedding, and the inability to use (i.e., wasting) the data that are not in the up and down bins. The large memory required to record the azimuthal data with sufficient accuracy is also an issue.
More importantly, the existing art for geosteering using directional measurements works only for steering up and down. There are many cases where the wellbore has to move azimuthally to avoid exiting the pay zone.
A need therefore exists for methods and techniques of extracting and analyzing the azimuthal dependence of directional logging measurements, using measurements taken at all the azimuthal angles, for characterizing the earth formation and for steering wells during drilling with improved accuracy.
A need further exists for providing the bedding azimuth from the directional measurements, and generating measurements that can be used for well placement in up/down or azimuthal steering.
A need further exists for methods of utilizing these directional measurements in real-time to obtain bed boundary distances and to obtain accurate earth models such that a geosteering decisions can be made for well placement.
A need further exists for a method of detecting the presence of resistivity anisotropy in formation layers adjacent near-vertical wells.
A still further need exists for an efficient system that provides such directional measurements, analyzes them downhole, and transmits relevant information to surface to facilitate geosteering up/down or azimuthally during well placement. It would be further advantageous if such a system could provide distance-to-boundary information during the sliding phases of drilling (i.e., no drill string rotation) as well as when the system/tool is rotating.